In the past several years, there have been many advancements in the coating industry. The overall performance of all coatings has increased with the introduction of epoxies, urethanes and polyesters, which have better adhesion, abrasion and chemical resistance, along with increased gloss retention for high quality paints. The selection of a paint or coating system for any given situation will require certain considerations: (1) the environment, (2) degree of surface preparation, (3) economics. After all these factors have been considered, select a system that will provide the best protection and general appearance for the longest possible time, at the lowest square foot cost per year and per mil thickness applied. The most important factor in the application of coatings is the human factor. More specifically, the selection of a competent paint/coating applicator and the inspection of the paint/coating process is where the success of the job lies. And, if applied correctly, it should not fail prematurely. All paint and coatings do have a life expectancy. This paper has two objectives: (1) selection of a paint and coating contractor; (2) inspection of the coating process, including the final product. The above two objectives are related to the paint/coating of oil and gas installation facilities in the field.

Often the oil operator fails to recognize the importance of a careful study of the prime mover, yet each well that does not flow involves a problem in the selection and application of a suitable prime mover. Many formulas have been derived to determine the prime mover size. Basically, these formulas give essentially the same results when the same allowances have been made. An overall multiplier is generally applied without much thought as to the exact factors involved. Sometimes, very important factors are overlooked in obtaining an efficient, economical prime mover installation.

Presents explanations of different types of bottom-hole pumps available to produce gaseous wells. Case histories indicating increases gained by various operators with proper pump installation will be given.

Many pump designs and combinations of metals have been developed to meet the various problems (or conditions) found in an oil well. In presenting our thoughts on "The Proper Selection of an Oil Well Pump" we will, therefore, first classify the problem found in the well and then present our suggestions as to the proper design and combination of metals to be used in building the pump to meet the specific conditions of the well.

This paper discusses the primary factors to consider in the sizing of ANSI standard centrifugal pumps for production and plant applications. Practical information on selecting equipment for present and future requirements will be discussed. Material selection, mechanical seal selection, and pump modifications will be covered as part of the selection process. Explanation and calculations of NPSH and its relation to cavitation and pump sizing will be briefly mentioned. A basic overview of electric driver selection will also be touched upon.

The proper selection of an artificial lift system for a waterflood project will greatly influence the overall economics of the project. To achieve the most favorable economics, the lift system should have sufficient flexibility to handle the predicted range in producing rates, under the anticipated operating conditions, with minimum investment and operating costs. The optimum selection of a lift system depends on the design engineer's knowledge of (1) the factors which will influence the operation of the lift equipment (2) the advantages and disadvantages of the basic lift system and (3) the investment and operating costs. Two factors, common to all waterflood projects, normally considered first in the analysis of the optimum lift system are maximum anticipated fluid production and lift depth.

As the use of special fluids to complete or workover wells has become accepted practice, the number of completion and workover products on the market has increased considerably. Because of this, the selction of the fluid which will provide the best performance at the most efficient cost is a critical question. A review of the basic functions of a completion or workover fluid is presented. In addition, a discussion of the various types of completion and workover fluids is included. A decision chart is presented in order to systematize the selection process.

There have been many papers presented and many discussions about producing multiple completion wells. In fact, two papers were presented last year at the 5th Annual Short Course. We do not intend to cover the entire field of pumping multiple completion wells but must, of necessity, review some of the past history and accomplishments in this field. Dually completed wells first came into being during the early 1940s for two reasons: 1) shortage of steel (tubular goods) 2) Increased demand and price of oil. Dual completions of that day served their purpose and they also disclosed many complex problems to their operators. At that time, there were no specialized tools and practices for dual completions. The early tools were modifications of accepted tools and practices for standard single completions. Cementing techniques, while acceptable for single completions, were found to be unsatisfactory for duals as they allowed the producing pays to commingle. Imperfect packer seals were another common cause of failure.

Prior to a sound selection of injection pumps for waterflood service many factors are to be considered. With the consideration of plunger pumps versus centrifugal pumps the basic advantages of each must be carefully taken into account. When choosing one of these pumps for an individual flood project, the anticipated initial and future injection conditions for that system are of primary importance in determining the most economical type installation. Past experience with regard to initial investment and operating costs with each pump is an excellent guide toward the most advantageous decision to the operator.

API Standard 11 AX, Subsurface Pumps and Fittings, sets forth specifications covering sucker rod pumps and establishes dimension requirements to assure interchangeability of component parts. No material specifications or guidelines for the proper application of the various API pumps are given. This report was prepared by NACE Task Group T-lF-12 and is intended to serve as a supplement to API 11 AX. It presents general recommendations of metallic materials for the construction of sucker rod pumps for service in a hydrogen sulfide environment. Only pumps with one piece barrels and metal plungers are considered. The recommended materials are presented in tabular form and in a preferred order of listing for nine different environments with varying degrees of abrasion and hydrogen sulfide corrosion. The materials recommended are in common use and should perform satisfactorily when used in the specified environment. In certain circumstances other materials could also be satisfactory. The materials recommended in Tables 1, 2, and 3 and the order in which they are listed are based on the experience and judgment of the Task Group members. These recommendations are not intended to preclude the development and testing of new materials for improvement of sucker rod pump performance. Tables 4-10 list some of the materials commonly used in sucker rod pumps along with pertinent chemical and physical properties. The numbering system for the steels is from the AISI classification, the brasses are identified by numbers from the Copper and Brass Research Association, and the copper-nickel alloys carry the International Nickel Company designations. The use of specific alloy numbers should be encouraged. It is recognized that there are steels utilized in subsurface pumps with hardnesses greater than Rc 22** (valves, hard cases on barrel tubes, etc.). Experience has shown, however, that these materials give satisfactory service in the proper environment. A good chemical program is considered necessary for optimum performance of sucker rod pumping equipment in a corrosive hydrogen sulfide environment. Some corrosion inhibitors control rod breaks and tubing and flowline leaks but do not significantly affect pump life. Other corrosion inhibitors significantly increase pump life by promotion of oil wetting thus reducing friction as well as reducing rod on tubing wear, rod breaks, and tubing and flowline leaks. However, in some pump designs the inhibitor cannot reach some stagnant *areas and protective films may be removed by the rubbing action. There are chemicals used downhole that extend pump life by prevention of fouling, and still others that extend pump life by prevention of scale. Control of direct attack on pump materials, however, is best accomplished by materials selection in combination with chemical treatment.

The proper selection of metallic materials often makes the difference between a successful water injection program and an economic failure. Poor selection can often necessitate early abandonment or may limit the quantity of water injected by causing excessive shut-down time. In some floods, even a temporary stoppage of injection can cause oil to be bypassed in the formation and, if nothing worse, decrease the profit from the operation. For these reasons, much care in the selection of metallurgy throughout the water-handling operation is essential.

Care should be use in the selection and design of oil emulsion treating systems. We will discuss emulsion, how it is formed and treated, the treating systems that are used. When selecting a treating system, consideration should be given the cost of the unit, the effect of scale in the treating section, the effect of corrosion in the treating section and the corrosion effect on the treating unit itself, the use of pressure for gravity and volume control.

Selection of oil field prime movers is discussed, weighing the economic advantages and disadvantages of utilizing electric motor or gas engine drive. Selection and long term use of prime movers is presented from a "present worth" viewpoint.

In this paper, an attempt is made to present, from a practical standpoint, factors which should be considered in selecting subsurface pumps. Emphasis is given to rod-actuated equipment with discussions on special application pumps and the uses of exotic materials. Some time is spent on conditions which would dictate the use of hydraulic and submergible systems.

Experience developed in the Midcontinent Division of Exxon Co., U.S.A. indicates that well corrosion problems in rod pumped wells are directly related to the water cut of produced fluids. In general, severe corrosion problems as measured by excessive rod, pump and tubing failures, are predominant in wells that produce in excess of 30% water. Further, embrittlement and pitting resulting in reduced rod life and fatigue failures are accelerated by the presence of hydrogen sulfide in the produced fluids. Corrosion in rod pumped wells is controlled by maintaining an inhibitor film on all wellbore equipment exposed to produced fluids. The film can be formed and maintained as a well is produced by maintaining an adequate concentration of inhibitor in the produced fluids. The film can also be created by a short contact time with fluids containing a high inhibitor concentration. The film thus formed can be allowed to dissipate using frequent retreatment to maintain protection. Four methods are used to treat rod pumped wells with corrosion inhibitors: squeeze, batch flush. continuous injection, and circulation. The labor and material costs, investment, and treatment effectiveness vary with well characteristics for each method. The purpose of this paper is to present information for selecting the "best" corrosion inhibition technique for a given set of well conditions. "Best" method is defined as the most economical when both well servicing costs and corrosion inhibition expense are considered. This paper also presents formulas and guidelines for design of an effective treatment once the appropriate inhibition technique has been selected. The information presented is grouped in three main sections: (I) Selection of treatment methods; (2) Treatment design; and (3) Application of automatic chemical injectors.

The intent of this paper is to cover various types of oil field engines, their advantages and disadvantages, their rating, equipment that is available, installation features, and preventative maintenance, in order that proper selection of the prime mover may be obtained. The proper selection of a prime mover involves many factors other than the make and size of engine required. Too often only these factors are considered.

The selection of lubricated plug valves in the production field has been handled rather loosely over the years

This paper presents some stimulating ideas and thoughts on self-analysis and its effect on self improvement and self development.

The use of various separator designs, internals, and/or internal configurations can significantly enhance separation. The use of centrifugal inlet devices, in some cases, has been shown to increase vessel throughput up to eight hundred percent. Also, internal baffling and various coalescing media, including matrix plate coalescing sections and serpentine vanes, can improve the separator efficiency by eliminating short-circuiting and reducing foam. Inlet devices and vessel intemals are often used in retrofit applications to de-bottleneck facilities or simply improve performance using existing equipment. Furthermore, centrifugal separation may be utilized in vertical recycling separators and horizontal, in line recycling separators. These separators utilize tangential inlets or fixed vanes to generate centrifugal force and push the heavier liquid droplets to the vessel wall, scrubbing the gas. These technologies can be used as either

Cement plugs are one of the most important types of cement jobs ever performed. Therefore, they deserve the very best effort we can give to a problem. A successful plug job requires more attention to detail than most other cement jobs; the reason most of them fail is because they do not get this attention. The following guidelines will not guarantee success but they will provide a higher ratio of successes if used every time! Plugs need properties different from most other cement systems because they are intended for a different application entirely. Failure of cement plugs is most often due to a lack of hardness in the set cement. This lack of hardness usually can be traced to one or more of these common mistakes: 1. Mud contamination of the cement during placement 2. Drilling out too soon 3. Cement not initially designed for enough strength 4. Strong tendency of all people involved to want extra pumping time, so slurry is overretarded 5. Inaccurate BHT information - well is colder than expected because circulation effect isn"t considered and temperature is guessed rather than measured 6. Not enough cement volume used. Proper planning can eliminate these errors. Do all possible to eliminate these problems.

Successful primary cementing of shale completions requires slurry design considerations that conventional cementing operations typically do not consider. The unique petrophysical and geological properties of shale must be factored into the design along with future stimulation plans to provide zonal isolation and casing support. This paper focuses on shale wells cemented in the Arkoma Basin. Cement slurry design is a critical part of any successful cementing operation. This is particularly true for shale wells where the unique nature of shale and its completion methodologies put additional demands on the cement. Slurry design considerations and successful slurry formulations for the area will be discussed along with an overview of primary cementing practices. Operational considerations as they apply to cementing vertical and horizontal shale wells in the study area will be discussed. Conclusions and recommended practices for optimum results will also be presented.

Fluid inertia forces can be large enough to be considered in sucker rod simulators. Fluid inertia forces are larger with shallow wells, large pumps, high stroke rates, and/or lower compressibilities. Texas A&M U has developed a fluid inertia model. This paper covers the primary assumptions, the equations, the boundary conditions, the initial conditions, a parameter study based on field data, the solution method, the discretized equations, the pump position, and the calculation sequence.

This paper presents a simplified fast means of determining synchronous and non-synchronous pumping speeds for tapered as well as straight strings based on the Sloneger formulas but using up-dated constants. Fast means of calculating API maximum allowable loads are presented. Other formulas are also given.

Short-cycle rod pumping, as accomplished by a pumpoff controller or percentage timer, offers several benefits over conventional program timer pumping. Field results show that 1-power savings are realized by reducing both the kilowatt-hour consumption and kilowatt demand, 2- the pumping unit may be properly counterbalanced and the pump spaced under dynamic conditions to realize maximum pumping efficiency and minimize gas interference, and 3- by stabilizing the individual well production, the lease production may be monitored at the battery.

Shot peening has been utilized for many years in a variety of industries as a surface conditioning process for metals. When properly performed, shot peening imparts beneficial residual compression stresses to the surface and subsurface of a metal which enhances the fatigue resistance and corrosion tolerance properties. Shot peening is primarily used on components that operate in cyclic loading environments. Since sucker rods are subjected to alternating loads, shot peening should prove to be a viable method of retarding the effects of cyclic fatigue, thereby extending the service life of the rod. This paper will encompass: the shot peening method, effects, control, and benefits, shot peening vs. shot cleaning, residual stress measurement test results, high cycle rotational bending fatigue test results, testing of peened vs. non-peened new sucker rods, testing of shot peened vs. shot cleaned used rods, and testing of single peened vs. dual peened new rods to compare different peening processes and formulae.